Well Treatment

ABSTRACT

The present invention provides a method for the treatment of a subterranean formation which contains sand particles, said method comprising contacting said formation with a material capable of increasing the residual matrix strength of said particulate fine whereby to reduce or prevent their migration whilst minimizing any decrease in their permeability. Preferred materials include organosilanes and enzyme systems.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application is a continuation of U.S. application Ser. No.11/629,729, filed Dec. 15, 2006, which is a 371 U.S. National Phaseapplication of International Application No. PCT/GB2005/002390, filedJun. 17, 2005, which application claims priority to Great BritainApplication No. 0413584.4, filed Jun. 17, 2004, and Great BritainApplication No. 0424085.9, filed Oct. 29, 2004, which applications areincorporated herein fully by this reference.

This invention relates to a method of maintaining or enhancing fluidflow through subterranean formations, especially formations whichcomprise sand particles. More particularly, the invention relates to theprevention or reduction of particle (e.g. sand) migration inhydrocarbon-producing formations. Yet more particularly, the inventionconcerns the consolidation or strengthening of unconsolidated sand-likematerials (especially sand) in subterranean formations.

Hydrocarbons (i.e. oil or gas) are recovered from subterraneanformations by drilling a well bore into the formation and extracting thehydrocarbon. One of the factors which influences the rate of hydrocarbonproduction is the permeability of the formation which depends on thesize of its pores and internal capillaries.

Subterranean formations may typically comprise sandstone in which sandparticles are closely packed together. These close packed particles formthe basic structure of the formation (e.g. the sand particles maycomprise greater than 75%, preferably greater than 85%, e.g. greaterthan 95% by weight of the formation). Also present in subterraneanformations are small particulates (so-called “fines”) which may comprisesand and other fine particulate matter (e.g. quartz, clays, etc). These“fines” occupy the pores or interstitial spaces formed by the closepacking of sand particles.

When recovering hydrocarbons from subterranean formations containingparticulate fines, such as silt-sized or smaller particles, these veryfine particles have a tendency to be dislodged (e.g. due to instabilityof the formation). Where a large volume of fluid is forced to flowthrough such a formation, not only these particulates but also sandparticles which comprise the structure of the formation, may betransported to the surface and must then be disposed of Disposal oflarge volumes of sand produced from unconsolidated or poorlyconsolidated formations presents serious problems in terms of thelogistics of disposal and also has a huge impact on the economics of theoil and/or gas recovery process. Erosion of downhole equipment (e.g.pipelines, valves, etc.) due to the high velocities of particulates, andespecially sand particles, can also occur. Routine repair or replacementof such equipment can only be carried out during periods of shut-down inproduction which, again, has a significant economic impact on theproduction process. Fine particulates, and in particular, sand particlescan also become lodged in capillaries or a pore throat (i.e. the smallerinterstices between the grains of the formation). This at leastpartially plugs the pore spaces thereby causing a reduction inpermeability of the formation and hence a reduction in the rate ofhydrocarbon (e.g. oil) production.

Permeability impairment due to the production and movement of fineparticulates, and especially sand particles, is a major problem in theoperation of hydrocarbon-producing wells, particularly those locatedwithin very weak or unconsolidated formations. The result is usuallylost production due to plugging of gravel packs, screens, perforations,tubular and surface flow lines or separators. In addition to damagingpumps or other downhole equipment, erosion of casing and surfacefacilities may also occur. This is a major problem associated with sandmobilization. Indeed, sanding problems can in some cases cause loss orrecompletion of a well due to casing and/or hole collapse. As operatingconditions become more severe and the costs associated with well failureescalate so the need for effective sand control increases.

A number of methods for controlling sand production have been proposed.These include gravel packing, sand consolidation, critical productionrate, oriented/selective perforation, FracPacking, and variouscombinations of these methods. Such techniques are used in consolidated,poorly consolidated and unconsolidated sand formations.

Another approach to the problem of sanding is to operate the well underconditions not subject to failure. This is commonly termed “MaximumSand-Free” production. During operation this technique is implemented bygradually increasing the production rate until sand production starts.The rate is then decreased until sanding stops and production ismaintained at that level. The difficulty with this approach, however, isthat formations tend to become less stable with time. Through pressuredepletion and water in-flow, the maximum sand-free rate will usuallydecrease with time until production becomes uneconomic.

Chemical treatments have also been proposed which involve strengtheninga formation by injecting a chemical that bonds fine particulates and/orsand grains together. Chemical agents which have been used in sandconsolidation include furaldehydes, phenols and epoxy-based systems;however, these are not considered to be environmentally friendly. Afurther drawback to these systems is that these have a tendency to blockthe pores of the formation thereby reducing its permeability to both oiland water. This results in a dramatic reduction in the production rate.There has therefore been a widespread belief amongst those skilled inthe art that chemical treatment should be avoided.

There is thus a continuing need for alternative (e.g. improved) welltreatments which are able to prevent or reduce the production andmovement of fine particles, and especially sand particles, duringoperation of the well, in particular treatments which minimise thereduction in permeability that can occur when a fluid passes through aformation which comprises sand particles and which may also containadditional moveable fine particles.

To date, chemical treatments proposed for use in preventing particulatemigration, especially those for use in sand consolidation, have focusedon the need to form relatively strong chemical and/or physical bondsbetween the sand particles. This need arises from the misconception thata certain minimum strength has to be imparted to the formation in orderto prevent the movement of fine particulates and sand particles. This,however, results in the formation of stone or stone-like structures inwhich the interstices or pores between the particles of the formationbecome blocked and which therefore have low or zero permeability therebyfurther reducing production levels.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 shows the chemical reaction between active sites of a formationand a silanol molecule (top) and the chemical reaction between twosilanol molecules (bottom).

FIG. 2 shows the chemical reaction between different organosilanemolecules bound to the same particle and/or different particles.

FIG. 3 shows a cylindrical sand pack holder.

FIG. 4 shows the sand production (% of total mass of sand) duringconsolidation testing in a sand pack holder of the materials describedin Example 1.

FIG. 5 shows the pressure drop during sand production for each of thematerials described in Example 1.

FIG. 6 shows the reduction of permeability of a sand pack aftertreatment with each of the materials described in Example 1.

FIG. 7 shows the sand production (% of the total mass of sand) withincreasing fluid velocity during consolidation testing in a sand packholder of the material described in Example 2.

FIG. 8 shows the sand production (% of the total mass of sand) duringconsolidation testing in a sand pack holder of the materials describedin Example 2.

FIG. 9 shows the apparatus used as described in Example 3.

Surprisingly, we have now found that the production of fine particulatesand, in particular, sand production can be adequately controlled by theuse of chemical agents which impart small incremental forces or arelatively weak residual strength to the formation. Such agents arecapable of imparting sufficient resistance against sand particlemobilization but without unduly reducing the permeability of theformation after treatment, e.g. whilst maintaining a high level ofpermeability. In this way, the production rate can be increased withoutincreasing the production of fine particulates and/or sand particles.Furthermore, since the demand for strength in the particles of theformation matrix is low, this opens up the possibility of usingdifferent chemicals for the prevention or reduction of particlemigration in rock formations (e.g. for sand consolidation), in additionto the possibility of using chemicals previously proposed for use inpreventing particle migration but in much lower amounts. Productioncosts may therefore be significantly reduced and, if required, sandconsolidation may be carried out more frequently thereby still furtherimproving production levels.

Viewed from one aspect the present invention thus provides a method forthe treatment of a subterranean formation which contains sand particles,said method comprising contacting said formation with a material capableof increasing the residual matrix strength of said sand particleswhereby to reduce or prevent their migration whilst minimising anydecrease in the permeability of the formation. In a preferred method ofthe invention, said material is also capable of increasing the residualmatrix strength of particulate fines whereby to reduce or prevent theirmigration whilst minimising any decrease in the permeability of theformation.

Viewed from another aspect the invention provides the use for themanufacture of hydrocarbon well treatment compositions (e.g. sandconsolidation compositions) of a material capable of increasing theresidual matrix strength of sand particles contained within asubterranean formation whereby to reduce or prevent their migrationwhilst minimising any decrease in the permeability of said formation.

Viewed from a still further aspect the invention comprises a hydrocarbonwell treatment composition (e.g. a sand consolidation composition)comprising a carrier liquid containing a material capable of increasingthe residual matrix strength of sand particles contained within asubterranean formation whereby to reduce or prevent their migrationwhilst minimising any decrease in the permeability of said formation.

For the present purposes, the term “sand particles” encompasses anysiliceous material which comprises the structure of a subterraneanformation. The terms “fines”, “fine particulates” and “particulatefines” are intended to encompass any particles present in the pores orinterstitial spaces present in the formation. These latter particlestypically have a mean particle diameter of <50 μm. Typically, these willbe small enough to pass through the openings of the smallest sievecommonly available (approx. 37 μm openings). Many different materialscan be found in subterranean formations and thus the composition of thefine particulates may vary widely. In general, fines may include quartzand other minerals, clays, siliceous materials such as sand, etc. Themethods and compositions herein described find particular use intreating sandstone formations, e.g. sand particles.

As used herein, the term “residual matrix strength” is a measure of theability of a particulate matrix to hold together the individualparticles under a given set of conditions (e.g. temperature, pressure,fluid flow, etc.). The residual matrix strength of a matrix may bequantified in several ways, e.g. in terms of the applied force,pressure, fluid velocity, etc. required to destroy or “break” thematrix.

Materials suitable for use in accordance with the invention are thosewhich are capable of imparting a relatively weak residual matrixstrength to the sand particles contained within a formation, for examplea residual matrix strength of the order of 0.1 to 500 bar (e.g. about0.1 bar), preferably 1 to 200 bar, more preferably 10 to 60 bar, yetmore preferably about 50 bar. Preferred materials are capable ofincreasing the residual matrix strength by 20 to 100 bar, e.g. about 50bar.

As used herein, the term “permeability” means the capacity of a porousmedium (e.g. the particulate matrix) to transmit a fluid, i.e. theresistance to flow of a liquid through a porous material. Permeabilityis measured using Darcy's Law:

Q=k·ΔP·A/μL

where

-   -   Q=flow rate (cm³/s)    -   ΔP=pressure drop (atm) across a cylinder having a length L (cm)        and a cross-sectional area A (cm²)    -   μ=fluid viscosity (cp)    -   k=permeability (Darcy)

Preferably, the reduction in permeability of the formation followingtreatment in accordance with the invention will be less than 40%,preferably less than 30%, more preferably less than 20%, e.g. less than10%. Yet more preferably, the formation will have substantially the samepermeability both prior to and following treatment in accordance withthe invention.

Particularly preferred for use in the invention are materials whichincrease the residual matrix strength of the sand particles by 20 to1,000%, preferably 100 to 200% without decreasing the relativepermeability of the formation by more than 50 to 1%, preferably 30 to1%, e.g. 10 to 1%.

Particularly preferred materials for use in the method of the inventionare those capable of increasing the residual matrix strength of the sandparticles such that the % sand production (% of the total mass) in thetest described in Example 1 presented herein is less than 20%,preferably without decreasing the relative permeability of the formationby more than 50 to 1%, preferably 30 to 1%, e.g. 10 to 1%.

Further preferred materials for use in the method of the invention arethose capable of increasing the residual matrix strength of the sandparticles such that break occurs in the test described in Example 3presented herein at a confining pressure of at least 250 bar (e.g. atabout 0.4 l/min), more preferably at least 270 bar, preferably withoutdecreasing the relative permeability of the formation by more than 50 to1%, preferably 38 to 1%.

Further preferred materials for use in the invention are those capableof imparting a residual matrix strength to the sand particles such thatin the test described in Example 1 herein the treated sand particles canwithstand a pressure drop of at least 10,000 mbar, preferably at least15,000 mbar, without breaking Particularly preferably, such materials donot decrease the relative permeability of the matrix by more than 50 to1%, preferably 30 to 1%, e.g. 10 to 1%.

It is also preferred that the materials for use in the invention afforda matrix which is resilient, e.g. it has high compressive, tensile andbond strengths. Preferably, the particulate matrix should havesufficient resiliency to withstand the stress conditions resulting fromhigh fluid pressures and/or temperatures inside the formation, e.g.during testing, perforating, fluid injection or fluid production. Forexample, the matrix should be able to withstand a pressure pulse of atleast 10,000 mbar, preferably at least 50,000 mbar substantially withoutloss of its structure.

The amount of particulate fines and especially sand particles producedfrom any given rock formation on exposure to a fluid at a given velocitymay be expressed as a percentage of the original mass of the formation.Materials suitable for use in accordance with the invention are thosewhich are capable of minimising the production of particulate fines, andespecially sand particles, and will generally maintain the level ofproduction of particulates below 10%, e.g. below 8%, at a Darcy flowrate (Darcy velocity) of at least 0.3 cm/s. Materials which are able tokeep sand production levels within the range of from 1 to 4%, e.g. 1-2%,at a Darcy velocity of at least 0.3 cm/s are particularly preferred.

The nature and concentration of the agents used in the invention is suchthat these impart a relatively small increase in the residual matrixstrength of the sand particles. For example, it has been found that arest force roughly equivalent to the capillary forces (capillarytension) in water wetted sand (approx. 1 psi) is sufficient to stop (orat least limit) the mobilization of fine particulates, and especiallysand particles. A relatively small increase in the residual matrixstrength of sand particles can in turn result in a considerable increasein the Maximum Sand Free Rate (MSR). This has a huge economic impact forthose wells where the production rate is dependent on the MSR.

Materials for use in the invention are preferably dispersible or solublein a hydrocarbon (e.g. a C₁₋₂₀ alkane). Still more preferably, thematerials for use in the invention are also at least partially watersoluble (e.g. water soluble). In some cases the material for use in theinvention will be more soluble in hydrocarbon than in water. Morepreferably, however, the materials for use in the invention will be moresoluble in water than in hydrocarbon. The materials for use in theinvention may, for example, partition between hydrocarbon and water at aratio in the range 5:95 to 90:10, more preferably 10:90 to 70:30, forexample, about 40:60. The ability to partition in this way enables thematerial to be delivered to the formation in a hydrocarbon carrier (e.g.substantially without decomposition) whilst at the same time enablingit, if necessary, to undergo reaction on contact with connate water atthe desired point of action.

Materials for use in the invention include organosilanes, for exampleorganosilane hydrides, organosilane alkoxides and organosilane amines.Organosilane compounds have the advantage that they are typicallyoil-soluble and react with water. These are also biodegradable andenvironmentally acceptable (e.g. for DYNASYLAN AMEO: LC₅₀ fish=934 mg/l;EC₅₀ daphnia=331 mg/l; IC₅₀ algae=603 mg/l, biodegradability=67%, forDYNASYLAN bis-AMEO: LC₅₀ fish>200 mg/l; EC₅₀ daphnia>200 mg/l; IC₅₀algae=125 mg/l, biodegradability=64.5%, as tested according to OECD306). Organosilanes for use in the invention preferably have abiodegradability of at least 60%. Whilst not wishing to be bound bytheory, it is believed that organosilane compounds react with water andhydrolyse. The resulting chemicals then react with siliceous surfaces inthe formation (e.g. the surface of silica sand), coat any sandparticles, bind them in place by the formation of bridges and restricttheir movement. The advantage of bifunctional organosilanes is theirability to bind two particles together.

Particularly preferred organosilane compounds include those having atleast one hydrolysable bond. By a “hydrolysable bond” is meant a bondthat is capable of being cleaved on reaction with water. Preferably thehydrolysable bond will be attached to a silicon atom. In other words,the hydrolysable bond is preferably between Si and a second atom/groupin the molecule. Still more preferably the hydrolysable bond is onewhich may hydrolyse to produce a silanol (i.e. —Si—OH).

Whilst not wishing to be bound by theory, it is believed that thehydrolysis of an organosilane to produce a silanol may be critical tothe success of the method herein described. More specifically it isthought that the organosilane, upon contact with connate or residualwater in the formation, hydrolyses to form a silanol.

RRRSi—O-Group+water--->RRRSi—OH+HO-Group

This silanol is then believed to react with active sites (e.g. SiOHbonds) on the surface of the formation (i.e. sand particles) and/orcondense with another silanol molecule by forming —Si—O—Si— bonds (seeFIG. 1). Whilst the former reaction serves to covalently bond theorganosilane to particles (e.g. sand particles) comprising theformation, the latter enables the organosilanes to covalently bond toeach other. Bonds may form between different organosilane moleculesbound to the same particle and/or different particles (see FIG. 2). Theorganosilane therefore acts as a “glue” or “bridge” to bind or holdtogether the particles comprising the formation, thereby reducing oreliminating their movement when fluid flows through the formation.Bridging will typically occur between surfaces of particles which areseparated by up to 30 bond lengths, preferably 15-20 bond lengths, e.g.on grain-to-grain contact. In this way, the residual matrix strength ofthe formation is increased.

The amount by which the residual matrix strength is increased may dependon the number of bonds the organosilane forms with the sand particlesand/or the extent to which reaction occurs between differentorganosilane compounds, especially those bound to different particles.This, in turn, at least partially depends on how many silanol groups canbe formed per molecule.

Preferred organosilane compounds for use in the invention comprise 1 to12 hydrolysable bonds, more preferably 3 to 9 hydrolysable bonds, stillmore preferably about 6 hydrolysable bonds. Such compounds possessinghydrolysable bonds may well be able to self-condense and/or polymeriseafter hydrolysis of one or more of the hydrolysable bonds. Theafore-mentioned preferred numbers of hydrolysable bonds thereforerelates to the number present in the monomeric form of the compound(i.e. one which has not undergone oligomerisation or polymerisation).For example, aminotriethoxysilane contains 3 hydrolysable bonds (i.e.3×Si—OEt) and bis-(triethoxysilylpropyl) amine contains 6 hydrolysablebonds (i.e. 6×Si—OEt). In the organosilane compounds for use in theinvention, the hydrolysable bonds present may be different, but morepreferably are the same.

In preferred organosilane compounds for use in the invention at leastone hydrolysable bond comprises part of a terminal group. Morepreferably, all of the hydrolysable bonds comprise part of a terminalgroup. By a “terminal group” is meant a group which is located at oneend of the molecule. This is in contrast to a side group or pendantgroup which is attached to another part of the molecule. For example, inthe compound aminotriethoxysilane, the amino group and the —Si (OEt)₃groups are terminal groups. In contrast in the compoundbis-(triethoxysilylpropyl) amine the —Si(OEt)₃ groups are terminalgroups, whereas the amine group is not.

In particularly preferred compounds for use in the invention all bondsother than the afore-mentioned hydrolysable bonds, are stable to theconditions to which it is exposed in use (e.g. stable to hydrolysis insea water). Preferably the remaining bonds in the molecule arecarbon-carbon, carbon-hydrogen, silicon-carbon, nitrogen-carbon,oxygen-carbon and/or nitrogen-hydrogen bonds.

Preferred organosilane compounds may also include an amine group. Thepresence of an amine group may result in stronger adhesion of theorganosilane to the particles of the formation and/or increase thestability of the organosilane to high temperatures and/or pressures.This may be due to the fact that the amine group may form further bonds(e.g. covalent, hydrogen and/or ionic bonds) between the organosilaneand the formation and/or other organosilanes. Preferably the amine is aprimary amine (i.e. —NH₂), still more preferably a secondary amine (i.e.—NH—).

Particularly preferred are those organosilane compounds which includemore than one functional group, e.g. bifunctional organosilanes, orthose compounds which are capable of self-polymerisation to producebifunctional molecules. By “bifunctional organosilane” is meant anorganosilane comprising two separate Si atoms, each of which forms partof at least one hydrolysable bond. Bifunctional organosilanes thereforeadvantageously afford, upon contact with water, at least two separate—Si—OH groups, which may each undergo any of the above-describedreactions either with the particles present in a formation and/oranother organosilane. Bifunctional organosilanes therefore increase thedegree of bonding which occurs between different organosilanes,especially those bound to different particles in the formation.Bifunctional organosilanes containing both alkoxide and amine groups areparticularly preferred.

Monofunctional organosilanes are also useful in the method of theinvention. By monofunctional organosilane is meant an organosilanecomprising one Si atom that forms part of at least one hydrolysablebond. In contrast to bifunctional organosilanes, monofunctionalorganosilanes tend to allow for less bonding to occur between differentorganosilanes, particularly those bound to different particles in theformation. Monofunctional organosilanes containing an amine group areparticularly preferred.

It is particularly preferred in the method of the invention to use amixture of a bifunctional and a monofunctional organosilane. Forinstance, the mixture may comprise a bifunctional to monofunctionalorganosilane ratio of 75:25 to 25:75, more preferably 60:40 to 40:60,still more preferably about 50:50. These ratios of bifunctional tomonofunctional organosilanes have, in many cases, been found to yieldthe desired balance of inter-compound condensation which may “glue” theparticles together whilst at the same time providing adequate bonding tothe siliceous surfaces of the formation (i.e. the sand particles). This,in turn, may be responsible for providing a consolidated mass having agel-like structure. An advantage of the gel-like structure is that itmay exhibit viscoelastic properties, i.e. it is not brittle.

Representative examples of organosilane compounds which are suitable foruse in the invention are organosilane alkoxides, organosilane esters,organosilane oximes, organosilane halides and organosilane hydrides.These compounds contain at least one —Si—OR, —SiO(O)CR, —SiO—N═CRR′,—SiX and —SiH group respectively (wherein R and R′ may be C₁₋₂₀ alkyland X is a halogen). Hydrolysis of compounds containing these groupsyields, in addition to a silanol (i.e. —Si—OH), —ROH, —RC(O)OH,—R′RC═NOH, —HX and —H₂ respectively wherein R, R′ and X are ashereinbefore defined.

Particularly preferred organosilane compounds are organosilane alkoxidesand organosilane esters. These undergo hydrolysis to afford, in additionto a silanol, alkanols and acids respectively. Neither of thesecompounds generally cause problems (e.g. due to side reactions) inhydrocarbon wells. Preferred organosilane compounds for use in theinvention comprise a group of the formula —Si—OR wherein R is C₁₋₂₀alkyl, more preferably C₂₋₆ alkyl, e.g. ethyl. Other preferredorganosilane compounds comprise a group of the formula Si—O(O)CR whereinR is C₁₋₂₀ alkyl, more preferably C₂₋₆ alkyl, e.g. methyl.

Organosilane compounds suitable for use in the invention include thosecompounds of formula I:

R¹R²R³Si—R⁴  (I)

(wherein

R¹, R² and R³ are each independently selected from hydrogen and organicradicals having from 1 to 50 carbon atoms; and

R⁴ is hydrogen, an organic radical having from 1 to 50 carbon atoms, ora group —OR⁵ in which R⁵ is an organic radical having from 1 to 50carbon atoms;

with the proviso that at least one of R¹, R², R³ and R⁴ is other thanhydrogen).

In the compounds of formula I, R¹-R⁵ are preferably selected fromoptionally substituted alkyl, alkenyl, aryl and alkoxy groups havingfrom 1 to 18, preferably from 1 to 10, e.g. 1 to 6, carbon atoms.Optional substituents which may be present include alkoxy (e.g. C₁₋₆alkoxy), amino, silyl and silyloxy groups. The groups R¹-R⁵ may furtherbe interrupted by one or more heteroatoms, preferably by N, O or S, e.g.by a group —NR¹² where R¹² is H or C₁₋₆ alkyl.

Preferred for use in the invention are esters of organosilanes, i.e.those compounds of formula I in which R⁴ is —OR⁵ where R⁵ is C₁₋₈ alkyl,e.g. C₁₋₆ alkyl.

Preferred compounds for use in the invention are those represented byformula (II):

R¹⁰ _(b)(RO)_(3-b)Si—R¹¹  (II)

(wherein

b is zero or a positive integer from 1 to 3, preferably 0 or 1, e.g. 0;

R¹⁰ is a substituted or unsubstituted, preferably unsubstituted, alkylgroup having from 1 to 6 carbon atoms, e.g. C₁ alkyl;

each R is independently a substituted or unsubstituted, preferablyunsubstituted, alkyl group having from 1 to 18 carbon atoms, e.g. 1 to 6carbons, or a —COR¹³ group wherein R¹³ is an optionally substituted,preferably unsubstituted, C₁₋₁₈ alkyl, e.g. C₁₋₆ alkyl group; and

R¹¹ is a substituted or unsubstituted alkyl group having from 1 to 40carbon atoms (preferably 1 to 18 carbon atoms, e.g. 1 to 8 carbons) andwhich is optionally interrupted by one or more heteroatoms; or

R¹¹ is a group of the formula —(CH₂)_(x)-A-(CH₂)_(y)—Si(OR)₃ in which Ais an organic linking group or a group comprising an atom having a lonepair of electrons (e.g. a N, P or S atom); x is 0 or a positive integer,preferably from 1 to 10, more preferably 1 to 4, e.g. 2 or 3; y is 0 ora positive integer, preferably from 1 to 10, more preferably 1 to 4,e.g. 2 or 3; and R is as hereinbefore defined).

In preferred compounds of formula II, R is a C₁₋₆ alkyl group, morepreferably a C₂₋₄ alkyl group, for example, methyl or ethyl. Inparticularly preferred compounds of formula II, each R is the same.

Preferred compounds of formula II are also those wherein R¹¹ is anunsubstituted alkyl group (e.g. R¹¹ may be propyl, butyl, pentyl, hexyl,heptyl, octyl, nonyl, decyl or dodecyl, especially preferably octyl).

In particularly preferred compounds of formula II, R¹¹ is a substitutedor unsubstituted, preferably substituted, alkyl group (e.g. asubstituted C₁₋₁₂ alkyl group). Preferred alkyl groups include propyland butyl. Substituents which may be present include —NH₂, —NHR′ and—NR′R″ wherein R¹ and R¹¹ independently represent C₁₋₆ alkyl groups.

Particularly preferred organosilanes for use in the invention are thoserepresented by formula III:

(RO)₃Si—(CH₂)_(x)-A-(CH₂)_(y)—Si(OR)₃  (III)

(wherein

each R is independently a substituted or unsubstituted, preferablyunsubstituted, alkyl group having from 1 to 18 carbon atoms, e.g. 1 to 6carbons, or a —COR¹³ group wherein R¹³ is an optionally substituted,preferably unsubstituted, C₁₋₁₈ alkyl, e.g. C₁₋₆ alkyl group;

A is an organic linking group or a group comprising an atom having alone pair of electrons (e.g. a N, P or S atom);

x is 0 or a positive integer, preferably from 1 to 10, more preferably 1to 4, e.g. 2 or 3; and

y is 0 or a positive integer, preferably from 1 to 10, more preferably 1to 4, e.g. 2 or 3).

In formulae II and III, the function of group A is as a linking moietyand its precise chemical nature is of lesser importance provided thisfunction is fulfilled. Generally, however, it will comprise a chain 1 to20 atoms long, preferably 1 to 10, especially 1 to 5. Examples ofsuitable linkers include both linear and branched alkylene chains whichmay be interrupted by heteroatoms such as nitrogen and oxygen.

In formulae II and III, x and y will generally be identical.

Unless otherwise specified, any alkyl, alkenyl or aryl group referred toherein may be mono- or poly-substituted and, with the exception of aryl,may be branched or unbranched.

In preferred compounds of formula III, R is a C₁₋₆ alkyl group, morepreferably a C₂₋₄ alkyl group, for example, methyl or ethyl. Inparticularly preferred compounds each R is the same.

Preferred compounds of formulae II and III are also those wherein A is agroup comprising an atom having a lone pair of electrons, especiallynitrogen. Preferably A will be a group —NH or —NR⁶ where R⁶ is C₁₋₆alkyl.

Other preferred organosilanes for use in the invention are thoserepresented by formula IV:

R⁹ _(a)(RO)_(3-a)Si—(CH₂)_(z)—NR⁷R⁸  (IV)

(wherein R⁷ and R⁸ are independently hydrogen or a substituted orunsubstituted, preferably unsubstituted, alkyl group having from 1 to 6carbon atoms; z is a positive integer, preferably from 1 to 20, morepreferably 1 to 8, e.g. 3 or 8;a is zero or a positive integer from 1 to 3, preferably 0 or 1 (e.g. 0);R⁹ is a substituted or unsubstituted, preferably unsubstituted, alkylgroup having from 1 to 6 carbon atoms (e.g. C₁) andR is as hereinbefore defined in relation to formula III).

In preferred compounds of formula IV, at least one of R⁷ and R⁸ ishydrogen. More preferably both R⁷ and R⁸ are hydrogen. Further preferredcompounds of formula IV are those wherein z is at least 2, still morepreferably z is at least 3 (e.g. z is 3).

It is particularly preferred in the method of the invention to use amixture of a compound of formula III and a compound of formula IV. Forinstance, the mixture may comprise a compound of formula III to acompound of formula IV in a ratio of 75:25 to 25:75, more preferably60:40 to 40:60, still more preferably about 50:50.

Suitable organosilanes include 3-amino-propyltriethoxysilane, bis(triethoxysilylpropyl) amine, 3-(diethoxymethylsilyl) propylamine,trimethoxyoctylsilane, triethoxyoctylsilane,4,4,15,15-tetraethoxy-3,16-dioxa-8,9,10,11-tetrathia-4,15-disilaoctadecane,and any combination thereof. Such compounds are available commercially,e.g. from Degussa (Hanau, Germany) under the tradenames DYNASYLAN 1126,DYNASYLAN 1122, DYNASYLAN 1506, DYNASYLAN OCTMO, DYNASYLAN OCTEO,DYNASYLAN AMEO and Si 69. A preferred combination of organosilanes foruse in the invention is that comprising 3-aminopropyltriethoxysilane andbis (triethoxysilylpropyl) amine, preferably in a ratio of 75:25 to25:75, more preferably 60:40 to 40:60, still more preferably about50:50. A particularly preferred mixture is that sold under the tradenameDYNASYLAN 1126.

Preferred esters of organosilanes include those containing amine groups.Whilst not wishing to be bound by theory the presence of the aminefunction appears to result in better adsorption of the organosilane tothe fine particulates, e.g. sand grains. It is also believed that thepresence of an amine group may contribute to the formation of a gel-likestructure having viscoelastic properties.

The amount of material to be used will vary widely depending on factorssuch as the nature of the particular material used, the nature (e.g.permeability, temperature, etc.) of the rock formation and so on. Theaverage particle/grain size of the sand particles will, for example,influence the strength of the matrix and thus the amount of chemicalagent needed to prevent or reduce particle migration. In general, theamount of material used will be sufficient to maintain the rate of flowof liquid through the formation following treatment and appropriateamounts may readily be determined by those skilled in the art.Typically, the organosilane may be employed in an amount in the range offrom 0.1 to 20% w/v, e.g. 1 to 5% w/v.

Preferably the amount of material to be used will be sufficient to coata substantial portion of the sand particles comprising the formation.More preferably sufficient material is supplied to coat 10 to 70% of theparticles, more preferably 20 to 60%, still more preferably 30-50%. Thisamount of material is capable of functioning as a bond or “bridge”between particles located in close proximity to one another. Thiscontrasts with many conventional procedures which either seek to coatthe entirety of particles comprising the formation or to solely treatother fines, e.g. clays, which are present within the structure of theformation. In general about 20 to 200 litres (e.g. about 50 to 150litres), more preferably 30 to 100 litres of organosilane per m³ of theformation will be employed.

Also suitable for use in the invention are enzyme systems. Thesecomprise an enzyme and a substrate for the enzyme whereby the action ofthe enzyme on the substrate results in the precipitation or depositionof a material which effectively strengthens the binding of fineparticulates. The material which is precipitated or deposited in theformation may be produced from a compound present in the rock formationprior to the introduction of the enzyme system. Alternatively, asuitable compound may be introduced into the well in addition to theenzyme and the substrate.

Enzymes suitable for use in the invention include those which remainactive under the conditions (temperature, pressure, etc.) found in therock formation to be treated. Typically, these will be water soluble.Preferably, the enzyme is a urease (EC 3.5.1.5). This may be isolatedfrom any plant, animal, bacterial or fungal source. Optionally, this maybe chemically modified provided it retains its desired catalyticactivity. Examples of suitable ureases include thermophilic orthermostable ureases, e.g. those isolated from Jack bean. Ureasessuitable for use in the invention are commercially available from Sigma.A particularly preferred urease is Urease Canavalia ensiformis (Jackbean) available from Sigma under the Product No. U1500.

Suitable enzyme-substrate combinations are ureases in combination withurea. Typically, these will be used together with an aqueous solutionwhich on contact with the enzyme-substrate system is capable of forminga precipitate which binds fine particulates, and especially sandparticles. A suitable solution for use with urease/urea is an aqueoussolution containing a salt of Ca, e.g. calcium chloride. The action ofurease on urea generates ammonia and CO₂. The CO₂ becomes trapped asbubbles of CO₂ which on contact with CaCl₂ generate CaCO₃. Although notwishing to be bound by theory it is believed the calcium carbonate iseffective in cementing individual fines, and especially sand grains.

The amount of enzyme/enzyme substrate to be used will vary depending onfactors such as the nature (e.g. permeability, temperature, etc.) of therock formation and so on. In general, the amount of enzyme/enzymesubstrate used will be sufficient to maintain the rate of flow of liquidthrough the formation following treatment and appropriate amounts mayreadily be determined by those skilled in the art. Typically, the enzymesystem may be employed in an amount of from 5 to 300 I.U./cm³,preferably less than 100 I.U./cm³, e.g. less than 50 I.U./cm³.

It is envisaged that treatment with a material as herein described couldbe at any stage in hydrocarbon production, i.e. before and/or afterhydrocarbon production (i.e. extraction of oil or gas from the well) hasbegun. Preferably, the treatment will be prior to hydrocarbon productionin order to mitigate against potential particulate migration andespecially sand migration.

Treatment is conducted by injecting the composition through a well intothe formation, generally employing pressures sufficient to penetrate theformation. Treatment times or period of shut-in will depend on a numberof factors including the nature of the formation and the degree ofconsolidation required, the nature and concentration of the chemicalemployed, the depth of perforations, etc. Typical shut-in times may bedetermined by those skilled in the art and will generally range from 2to 10 hours, preferably from 3 to 8 hours, e.g. about 4 to 6 hours.

Any conventional treatment methods may be used to supply the materialsto the production well. Such methods will include bull-heading, coiltubing and zonal isolation with packers. Of these methods, bull-headingwill generally be preferred. This is in contrast to prior art methodswhere treatment chemicals are generally placed at various points in theformation, e.g. placed by coiled tubing to spot this at the desiredsite. This is a more costly operation to perform. An advantage ofbull-heading is that the whole well is treated and at relatively lowcost. Bull-heading can be used for treatment of both vertical andhorizontal wells and treatment can be effected during short productionintervals. Suitable injection flow rates may be readily determined bythose skilled in the art, however preferred flow rates may lie in therange 2500 to 3000 litres/min. In general, the injection flow rate willnot be lower than about 500 litres/min.

Coiled tubing (CT) methods are less desirable for economic reasons butmay nevertheless be successfully used to supply the materials to thewell. Such methods are generally more appropriate for treating longhorizontal sections of the well. Suitable CT methods include thoseconventionally used in the field, e.g. roto pulse method, concentriccoiled tubing, etc.

In a particularly preferred aspect of the invention, the formation istreated with a pre-flush composition prior to treatment with a materialcapable of increasing the residual matrix strength of the formation. Thepurpose of a pre-flush composition is to invade substantially all of thepore space of the portion of the formation to be consolidated therebyremoving a large proportion of the water naturally present therein. Thisthen leaves essentially connate or residual water. The pre-flush alsoremoves any water present in the equipment, pipelines etc involved inthe system.

The use of a pre-flush composition is particularly preferred when thematerial used in the method of the invention is an organosilane. In thiscase, the pre-flush composition may function as a means to locate theorganosilane on the particles comprising the formation, rather than inthe pore spaces between the particles.

Whilst not wishing to be bound by any theory, it is believed that apre-flush composition may be used to remove substantially all of thewater present in the pore space of the formation, whilst at the sametime leaving behind those water molecules which surround the formationparticles (e.g. those which are bound thereto by hydrogen bonding). Thiswater is sometimes referred to as the “residual water” or connate water.The effect of the pre-flush treatment is thus to provide a substantiallydry formation (e.g. a formation comprising 1-25% water, (e.g. 1-10%water, preferably 2-5% water), typically 18-22% water.

When such a formation is subsequently treated with organosilane the onlywater present to cause hydrolysis is that surrounding the particles(e.g. the water molecules comprising the thin “film” or “shield” boundto the particles by hydrogen bonding). Hence hydrolysis substantiallyonly occurs in close vicinity to the particles and the silanols producedinvariably react with active sites (e.g. —Si—OH groups) on the particlesurface and/or other silanols nearby. The overall effect is to provide amatrix wherein adjacent particles are “glued” together. In contrast, few(if any) silanols are produced in the pore spaces (as there are no watermolecules there to cause hydrolysis) and few diffuse there from thesurface of the particles before becoming bonded thereto. Thus little (ifany) condensation/polymerisation reaction occurs in, or across, the porespace and it is essentially left open. This advantageously minimises anydecrease in the permeability of the formation which could occur as aconsequence of the consolidation treatment.

In selecting a pre-flush composition it is preferred to avoid a solventwhich is substantially water soluble since such solvents will retain atleast some of the water naturally present in the well. As a result,organosilane may hydrolyse and condense in the pore spaces beforecontacting the particles comprising the formation and potentially reducepermeability. Water immiscible solvents are therefore preferred for usein the pre-flush.

Preferred pre-flush compositions for use in the method of the inventionare therefore substantially water insoluble (e.g. immiscible withwater). Examples of suitable pre-flush compositions include crude oil,base oil, an aliphatic hydrocarbon (e.g. hexane), an aromatichydrocarbon (e.g. benzene or toluene) or a petroleum distillationproduct or fraction (e.g. kerosene, naphthas or diesel fuel). Preferablythe pre-flush composition comprises a petroleum distillation product,especially diesel fuel.

The pre-flush compositions for use in the invention should also besubstantially dry, e.g. contain less than 10% water, preferably lessthan 5% water, more preferably less than 3% water, e.g. less than 1%water.

The volume of preflush composition used is typically 1000 litres per m³of formation to be treated. Generally the composition will be introduced(e.g. by pumping or injection) into the formation at a flow rate of2500-3000 litres/min.

An after-flush or over-flush may also be optionally, but preferably,used in the method of the invention. An after-flush is typically doneafter injection of the material (e.g. the organosilane) capable ofincreasing the residual matrix strength of the formation. It serves todisplace any unreacted material out of the tubing (e.g. out of the first1-2 m of tubing) used to supply material to the well-bore. The samehydrocarbon liquids described above for use in the pre-flush compositionmay be used as an after-flush. Alternatively any convenient aqueous ornon-aqueous liquid may be used.

Whilst an aqueous fluid may be used as an after-flush (e.g. water oracid), it is preferred that the after-flush is non-aqueous. Inparticular it is preferred that the after-flush does not comprisegreater than 20% water, more preferably not greater than 10% water,still more preferably the after-flush comprises less than 5% water (e.g.less than 1% water). Still more preferably the after-flush does notcomprise an acid.

Thus viewed from a further aspect the invention provides a method forthe treatment of a subterranean formation which contains sand particles,said method comprising:

(i) pre-flushing said formation whereby to remove substantially allwater from the pore space or voids of the formation;

(ii) contacting said formation with a material capable of increasing theresidual matrix strength of the sand particles (e.g. an organosilane);and

(iii) optionally after-flushing said formation.

A preferred method of the invention consists essentially of (e.g.consists of) steps (i), (ii) and (iii). Another preferred methodconsists essentially of (e.g. consists of) steps (i) and (ii) (i.e. noafter-flush is used).

The treatment methods herein described are such that these may berepeated as necessary in order to prevent particle migration (e.g. tomaintain sand-free production) at minimum cost. For example, treatmentcan be repeated at various intervals in order to maintain sand-freeproduction throughout the lifetime of the well. Alternatively, if aSMART well concept is employed, treatment can be effected at each stageof opening of a new section or interval in the formation. With eachopening the well bore may be treated as herein described prior tohydrocarbon production.

Other conventional well treatments such as stimulation treatment,hydraulic fracture treatment and scale reduction treatment may be usedin conjunction with the method of the invention. These may precede orfollow the method of the invention. Preferably, however, the well isready to be put back onto production immediately after the method of theinvention.

In a typical method of the invention a subterranean formation whichcontains sand particles is pre-flushed (e.g. with diesel) to removesubstantially all water from the pore space in between the particles.The pre-flush is injected at a rate of 500-4000 litres, preferably2500-3000 litres/min and may take 1-2 hours to complete. It is estimatedthat after this pre-flush less than 10% water is present in theformation to be treated. A material (e.g. an organosilane) capable ofincreasing the residual matrix strength is then injected in ahydrocarbon carrier. This carrier is usually substantially anhydrous.The material is injected at a rate of 2500-3000 litres/min and may take1-2 hours to complete. Finally, an after-flush is usually injected intothe formation before the well is optionally, but preferably, shut-in.

The preferred shut-in period is a function of the conditions in the well(e.g. temperature, pressure etc) which affect the rate at whichconsolidation occurs. Typically, however, the shut-in period will befrom 3 to 24 hours, preferably 4 to 12 hours, for example, 6 to 9 hours.

The materials for use in the invention are preferably applied as adispersion or solution in a liquid carrier. The liquid carrier may beaqueous or non-aqueous. Preferably, this will comprise a non-aqueousorganic liquid, e.g. a hydrocarbon or hydrocarbon mixture, typically aC₃ to C₁₅ hydrocarbon, or oil, e.g. crude oil. Other suitable carrierliquids include aromatic hydrocarbons such as naphtha and diesel. Dieselis particularly preferred.

It is generally preferred to use a hydrocarbon carrier since these thiswill minimise the exposure of the treatment material (e.g. theorganosilane) to water. This means that reaction (e.g. hydrolysis)during passage down into the well to the formation to be treated isminimised or prevented. Preferably the hydrocarbon carrier issubstantially anhydrous. For example the hydrocarbon carrier preferablycontains less than 5% water, more preferably less than 2% water, stillmore preferably less than 0.5% water, e.g. less than 0.1% water.

Suitable hydrocarbon carrier liquids include crude oil, base oil, analiphatic hydrocarbon (e.g. hexane), an aromatic hydrocarbon (e.g.benzene or toluene) or a petroleum distillation product or fraction(e.g. kerosene, naphthas or diesel fuel). Preferably the hydrocarboncomprises a petroleum distillation product, especially diesel fuel.

The hydrocarbon carrier may also contain other additives known in theart for use in well treatment. Such additives may include surfactants,thickeners, diversion agents, pH buffers and catalysts. Preferably thehydrocarbon does not contain a catalyst. Still more preferably thehydrocarbon carrier consists essentially of a material capable ofincreasing the residual matrix strength (e.g. an organosilane) of sandparticles in a formation.

Preferably, the concentration of the well treatment agent in the carrierliquid will be in the range of 0.05-50% w/v, preferably 0.1 to 30% w/v,more preferably 1 to 10% w/v, e.g. about 5% w/v. A higher concentrationwill generally be used for deeper perforations. Typically about 300-3000litres of hydrocarbon carrier per m³ of formation to be treated will beused.

The materials herein described may be used in treating hydrocarbon wellsboth prior to and during production of sand, i.e. for wells that alreadyproduce sand (post-failure) thereby effectively prolonging the lifetimeof the well and those that potentially may produce sand (pre-failure).For example, potentially weak formations (e.g. those having a potentialfor sand production under the so-called TCS 2 test, i.e. at theborderline of the 217 Bar at 2 MPa confining pressure limit) could betreated in advance, i.e. on completion. In this way, the need forcomplex sand protection systems for completion of the well is avoided.Instead, much simpler and thus more cost effective sand protectionsystems can be used for completion, e.g. simple sand screens.

For existing wells where production is restricted by Maximum Sand Freerate, treatment in accordance with the invention enables the use of muchhigher flow rates. A higher draw down can therefore be employedresulting in an increase in the level of hydrocarbon production. Inreservoirs where a depletion strategy might be used to permit morecomplete recovery of hydrocarbon, treated wells can tolerate a muchhigher differential pressure (i.e. higher draw down) without sandproduction.

The process of the invention is particularly effective in increasingtail-end production in more mature wells where the rate of production ofhydrocarbon is limited by the Maximum Sand Free rate and high watercuts. Hitherto, such wells would tend to be shut down once theproduction rate reaches a cut-off level and thus becomes uneconomic.However, by treating these wells in accordance with the method hereindescribed the formation is stabilised to the extent that this cantolerate a higher differential pressure without sanding problems. Thisenables a sufficient boost in the production rate of hydrocarbon (e.g.an increase of as little as 50-100 m³ oil per day) that the well againbecomes viable. In this way, the lifetime of the well can be prolongedby several years. By boosting the production rate from existing wells,the huge costs involved in opening a new formation are avoided, or atleast delayed.

The methods herein described may be employed to stabilise any poorlyconsolidated or unconsolidated formation. These may comprise, inaddition to sand particles, a broad range of “particulate fines” asherein defined. For example, these may comprise quartz or other mineralssuch as feldspars; muscovite; calcite; dolomite; barite; water-swellableclays such as montmorillonite; beidellite; nontronite; saponite;hectorite and sauconite; or non-water-swellable clays such as kaoliniteand illite. Problems associated with the presence and movement of finesare most pronounced in sandstone-containing formations. Most preferably,the particulate fines herein described will thus comprise siliceousmaterials such as siliceous sand grains.

The wells themselves may be a naturally occurring consolidation orartificial consolidations. By artificial consolidation is meant a wellwhich has been treated with other chemical agents, e.g. otherconsolidating agents. Wells containing materials having silica orsiliceous surfaces are particularly suitable for application of themethod of the invention.

The method of the invention is particularly suitable for use informations comprising mainly sand. Preferred wells comprise greater than75% sand, more preferably greater than 85% sand, still more preferablygreater than 95% sand. By sand may be meant any material which consistsessentially of SiO₂.

Particularly suitable wells for use of the invention are those whichhave relatively short production intervals. Generally both horizontaland vertical wells can be treated, though vertical wells are preferred.The temperature of a well to be treated by the method of the inventionis preferably in the range 50-200° C.

The invention will now be described further with reference to thefollowing non-limiting Examples:

EXAMPLE 1

Various chemicals were tested for their ability to consolidate sandusing a cylindrical sand pack holder as illustrated in attached FIG. 3having the following dimensions: 209 mm (length)×65 mm (diameter) and atotal sand volume of 157 cm³. The cylindrical sand pack holder can besplit into two parts so that it is then possible to remove a partlyconsolidated sand pack, e.g. for strength testing, without destroyingit. The sand pack holder was connected with differential pressuretransducers and placed inside a heating cabinet. Two high-rate pumpswere used to generate flow velocities high enough to generate sandproduction, whereas a pulse free pump was used for permeabilitymeasurements. A controller was connected to the two high-rate pumps thatstepped up the rate according to a pre-programmed procedure.

Experimental Procedure:

-   -   1. The sand pack holder is filled with unconsolidated sand        (standardised Baskarp sand).    -   2. Brine is injected into the sand under vacuum.    -   3. Permeability at S_(w)=1 is measured.        -   If oil soluble chemical:    -   4. Lamp oil is injected until S_(wi) is established.    -   5. Permeability at S_(wi) is measured.    -   6. Inject chemical and shut-in for a desired period of time and        at a desired temperature.    -   7. The chemical is flushed out using brine (or lamp oil if using        an oil soluble chemical).    -   8. Permeability after treatment at S_(w)=1 (or at S_(wi) if        using an oil soluble chemical) is measured.        -   If oil soluble chemical:    -   9. Brine is injected until S_(or) is established.    -   10. Sand production is measured using a pre-programmed        procedure.

During sand production, the rate of fluid flow was stepped up from 0 to100 ml/min, each rate step lasting for 30 seconds. The sand was producedinto a beaker with overrun for the fluid. At the end of the experimentthe sand was collected using a 0.45 μm filter. The sand was then driedat 50° C. and weighed.

Reference experiments were performed in the exact same manner, exceptthat no chemical was injected into the sand pack. Instead, pure lamp oilor brine was injected depending on whether the chemical tested was oil-or water soluble.

Chemicals Tested: DYNASYLAN 1126 (Degussa AG):

-   3-Aminopropyltriethoxysilane and bis (triethoxy silylpropyl) amine

DYNASYLAN 1122 (Degussa AG):

-   Bis (triethoxy silylpropyl) amine

DYNASYLAN 1506 (Degussa AG):

-   3-(Diethoxymethylsilyl) propylamine

DYNASYLAN OCTMO (Degussa AG):

-   Trimethoxyoctylsilane

DYNASYLAN OCTEO (Degussa AG):

-   Triethoxyoctylsilane

Si 69 (Degussa AG):

-   4,4,15,15-Tetraethoxy-3,16-dioxa-8,9,10,11-tetrathia-4,15-disilaoctadecane    UREA/UREASE (Urease used: U1500 from Sigma Chemicals; concentration:    50 I.U./cm³)

Results:

In FIG. 4 the amount of sand produced is displayed as a percentage ofthe total mass of sand in the sand pack holder. FIG. 5 shows how thepressure drop across the sand pack varied during sand production foreach chemical. FIG. 6 shows the percentage reduction in permeability foreach chemical after treatment compared to before treatment.

Discussion:

The organosilanes have the advantage that they are oil-soluble and reactwith water. The urea/urease precipitates CaCO₃(s) in the matrix. Iftreatment with this latter system should fail, e.g. one gets a drasticreduction in permeability, one can easily remove the salt by use of anacid.

FIG. 4 shows that all the chemicals tested are capable of reducing sandproduction compared to the references. The urea/urease system has thebest ability to consolidate sand, but it also has the greatest impact onpermeability (see FIG. 6). The organo-silanes can be divided into twogroups with regard their sand consolidation ability: DS 1122, DS 1126and DS 1506 in one group, and DS OCTEO, DS OCTMO and Si 69 in the other.The first group has a very good performance. Whilst the second groupreduces sand production, this is not as much as the first organosilanegroup or the urea/urease system.

For some experiments, the pressure drop during sand production keptrising during the whole experiment, see FIG. 5. Some experiments,however, demonstrated a sudden and drastic reduction in the pressuredrop during sand production. This is caused by a complete breakdown ofthe sand matrix, i.e. a channel is formed through the whole sand pack inwhich the fluid is flowing freely. The chemicals that have the bestability to consolidate sand will not exhibit any breakdown-point duringthe sand production experiment.

EXAMPLE 2

The experiments described in Example 1 were repeated using variousconcentrations (3% and 5%) of DYNASYLAN 1126 (Degussa AG). Referenceexperiments were performed in the same manner except that lamp oil wasinjected into the sand pack holder instead of the organosilane mixture.The sand used in the tests was obtained from the Nome field (“Nome”sand).

FIG. 7 shows the sand production (% of the total mass of sand) withincreasing fluid velocity. The reference sample (no chemical) failsalmost immediately as evidenced by the rapid rise in sand production atlow fluid velocities. This results from a complete breakdown of the sandmatrix. The 3% DS 1126 sample is able to withstand fluid velocities upto about 0.14 cm/s before sand production levels are seen to rise to anyappreciable extent. However, the sand matrix does not breakdowncompletely and the sand production levels out at about 15%. The 5% DS1126 sample withstands velocities up to about 0.30 cm/s whilstmaintaining sand production levels below 5%. In FIG. 8 the amount ofsand produced is shown as a percentage of the total mass of sand in thesand pack holder for each of the three samples tested.

EXAMPLE 3 Hollow Cylinder Tests

A measurement of the strength of a sand matrix is provided by a hollowcylinder test using the following procedure:

1. Install and connect up the apparatus shown in FIG. 9. External radialdeformation is measured in two orthogonal directions. Also measured isthe pressure around the core, the injection pressure, injection rate andamount of sand produced.

2. A nominal pressure around the core of 2 MPa is imposed and radialflow of fluid (0.3 litres/min) is started with lamp oil to ensurecomplete saturation (duration: 10 mins).

3. Pressure around the core is increased in a first step (rate: 4MPa/time) and radial flow starts. At each pressure level the flow isconducted for approx. 5 mins at each of the following rates: 0.2 l/min,0.3 l/min and 0.4 l/min.

4. Pressure around the core is increased in 1 MPa steps and flowrepeated at each pressure level until the sample collapses.

The following results were obtained for various samples treated with DS1126 at different concentrations and in different carrier fluids:

Post- Sand Pre-treatment treatment Break at Production PermeabilityPermeability Permeability confining before Total Sand Test Type Ko@SwiKo@Swi Reduction pressure break Production Reference 387 mD* 245 bar @Quite a lot 8.0 gr (diesel 1124 Kw@″So″ 0.3 l/min before without DSbreak 1126) 5 vol % DS 390 md 225 mD 42% 277 bar @ 0.7 gr 1.78 gr  1126(diesel 901 Kw@″So″ 0.4 l/min as base fluid) 3 vol % DS 264 mD 167 mD36% 304 bar @ 0.3 gr 1.2 gr 1126 (diesel 610 Kw@″So″ 0.4 l/min as basefluid) Start at 275 bar 3 vol % DS 266 mD  50 mD 81% 25 bar @ 0.8 gr 2.4gr 1126 (Base oil 520 Kw@″So″ 0.4 l/min as base fluid) Start at 258 bar@ 0.3 l/min

The results show that use of DS 1126 (at 5 or 3 vol %) greatly reducessand production. Advantageously this is also achieved without muchreduction in the permeability of the formation.

EXAMPLE 4 Field Tests

Two wells at the Nome field have been successfully treated withDYNASYLAN 1126 in order to reduce sand production. Tests performed onNome cores have shown that a reduction in permeability of the core of upto 32-42% (e.g. about 40%) following treatment with a mixture of 3-5 vol% DYNASYLAN 1126 in diesel can be tolerated whilst at the same timeproviding effective sand consolidation. Such a reduction in permeabilityreduces the PI (Production Index) of the well by 10-15%. However, sincethe production of the well is not limited by PI but rather by sandproduction levels, such a reduction in PI is acceptable.

Prior to pumping the diesel/DYNASYLAN 1126 mixture, a pre-flush of baseoil was injected in order to displace free water in both the well andthe formation. The main pill of diesel/DYNASYLAN 1126 was displaced intothe formation by pumping a string volume base oil overflush. The wellwas then shut-in for 6-9 hours in order to allow the DYNASYLAN 1126 toreact with the formation.

The following oil production rates before and after treatment with thediesel/DYNASYLAN 1126 mixture were observed:

Oil production Oil production Rate before Rate after Treatment Treatment(Sm³/day) (Sm³/day) Well B-3H: 1700 4000 Well B-2H: 2200 2900

The total field production potential in the B-3H well increased by 2300Sm³ per day following treatment with DYNASYLAN 1126. Sand production wasalso dramatically reduced and virtually ceased.

EXAMPLE 5 Scratch Tests

A measurement of the strength of a sand matrix is provided by a scratchtest wherein a needle is applied under an increasing force until thesurface of the sand breaks (Schei, G., Larsen, I., Fjaer, E., 1999,SINTEF Petroleum Research Report No. 33.0710.00/02/99 “Scratch Testingas a Tool for Formation Strength Determination-Phase 2”. The results areshown in the table below:

Core Scratch Test (MPa) Ile Core (untreated) 0.39 ± 0.05 Ile Core (3 vol% DS1126) 0.88 ± 0.11 Ile Core (5 vol % DS1126) 1.56 ± 0.11 Garn Core (3vol % DS1126) 8.5 ± 1.2

The results show that use of DS 1126 (at 5 or 3 vol %) increases thestrength of the sand matrix.

1.-24. (canceled)
 25. A method for the treatment of a subterraneanformation which comprises sand particles, the method comprisingcontacting the formation with a material capable of increasing theresidual matrix strength of the sand particles whereby to reduce orprevent their migration whilst minimizing any decrease in thepermeability of the formation, wherein the material is produced by anenzyme system which comprises an enzyme and a substrate therefor. 26.The method of claim 25, wherein the material is capable of imparting aresidual matrix strength to the sand particles in the range of 0.1 barto 500 bar.
 27. The method of claim 26, wherein the material is capableof imparting a residual matrix strength to the sand particles in therange of 1 bar to 200 bar.
 28. The method of claim 25, wherein thematerial, on contact with the sand particles, effects a reduction inpermeability of the formation of less than 40%.
 29. The method of claim28, wherein the material, on contact with the sand particles, effects areduction in permeability of the formation of less than 30%.
 30. Themethod of claim 25, wherein the material is capable of increasing theresidual matrix strength of the sand particles by 20% to 1,000%, withoutdecreasing the permeability of the formation by more than 50% to 1% 31.The method of claim 30, wherein the material is capable of increasingthe residual matrix strength of the sand particles by 100% to 200%. 32.The method of claim 30, wherein the material is capable of increasingthe residual matrix strength of the sand particles without decreasingthe permeability of the formation by more than 30% to 1%.
 33. The methodof claim 25, wherein the enzyme system comprises a urease.
 34. Themethod of claim 33, wherein the enzyme system comprises a urease incombination with urea.
 35. The method of claim 33, wherein the urease isisolated from Jack bean.
 36. The method of claim 35, wherein the ureaseis Urease Canavalia ensiformis.
 37. The method of claim 33, wherein theurease enzyme is in combination with urea and wherein the method furthercomprises the use of an aqueous solution containing a salt of calcium.38. The method of claim 37, wherein the salt of calcium is calciumchloride.
 39. The method of claim 25, wherein the enzyme and thesubstrate therefor are employed in an amount of from 5 to 300 I.U./cm³.40. The method of claim 39, wherein the enzyme and the substratetherefor are employed in an amount of less than 100 I.U./cm³.
 41. Themethod of claim 25, wherein the enzyme system is applied as a dispersionor solution in a substantially anhydrous hydrocarbon carrier.
 42. Amethod for the treatment of a subterranean formation which comprisessand particles, the method comprising: (i) pre-flushing the formationwhereby to remove substantially all water from the pore space or voidsof the formation; (ii) contacting the formation with an enzyme systemwhich comprises an enzyme and a substrate therefor, wherein the systemproduces a material capable of increasing the residual matrix strengthof the sand particles; and (iii) optionally after-flushing theformation.
 43. The method of claim 42, wherein the enzyme systemcomprises a urease.
 44. The method of claim 42, wherein the material iscapable of imparting a residual matrix strength to the sand particles inthe range of 0.1 bar to 500 bar.
 45. A hydrocarbon well treatmentcomposition comprising a carrier liquid comprising an enzyme systemwhich comprises an enzyme and a substrate therefor, wherein the systemproduces a material capable of increasing the residual matrix strengthof sand particles contained within a subterranean formation whereby toreduce or prevent their migration whilst minimizing any decrease in thepermeability of the formation.
 46. The composition of claim 45, whereinthe enzyme system comprises a urease.
 47. The composition of claim 45,wherein the material is capable of imparting a residual matrix strengthto the sand particles in the range of 0.1 bar to 500 bar.